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WHAT WE DO
Employing a full compliment of technical, operating and administrative staff,
Enerplus has proven itself an efficient operator, developer and acquisitor.
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Created in 1986, Enerplus is Canada's oldest and largest conventional oil and gas
income fund with a diverse oil and natural gas asset base located primarily in
Western Canada. The Fund pays investors a large portion of the net cash flow from
its crude oil and natural gas properties on a monthly basis. Employing a full
complement of technical, operating and administrative staff, Enerplus has proven
itself as an effective and efficient operator and developer over the last 17 years and
is a leader in the income fund sector. Our growth has been achieved through
accretive acquisitions and low-risk development versus the higher risk exploration
activities pursued by more traditional exploration and production companies.
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Our growth has been
achieved through accretive
acquisitions and low-risk
development.
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| PRODUCTION |
Enerplus achieved average daily production volumes of 62,784 BOE during 2002,
virtually unchanged from those levels attained during 2001 by the combined
Enerplus and EnerMark funds. The Fund's December exit production rate of
67,800 BOE/day reflects the additional volumes associated with the Celsius
acquisition that closed in October of 2002. Enerplus enjoys an above-average
reserve life index of 13.8 years, one of the highest in the sector. Enerplus operates
approximately 65% of current production and owns interests in over 10,000 wells
producing from over 250 properties. The property and product diversity within
the Fund minimizes the risks associated with any single property, area,
or commodity.
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| RESERVES |
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Enerplus ended 2002 with a record 330.4 MMBOE of established reserves, up 6%
from 2001 and the highest level of reserves achieved in the Fund's history.
Acquisition activities, net of dispositions, added 26.0 MMBOE of established
reserves with development activities resulting in the addition of 14.9 MMBOE of
established reserves, also a record achievement. Significant shallow natural gas
reserve additions were realized at Medicine Hat, Hanna Garden, Verger, and
Countess while major oil-related reserve additions were achieved at Giltedge,
Joarcam and Gleneath.
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|
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| Total established reserves at December 31, 2001 |
113.7 |
1,081 |
18.5 |
312.4 |
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| Proven, producing |
94.9 |
787 |
14.0 |
240.1 |
| Proven, non-producing |
10.3 |
215 |
2.0 |
48.1 |
| Total proven |
105.2 |
1,002 |
16.0 |
288.2 |
| Total probable at 50% |
16.7 |
139 |
2.3 |
42.2 |
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| Total established reserves at December 31, 2002 |
121.91 |
1,141 |
18.3 |
330.4 |
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|
| Acquisitions |
94.8 |
37.6 |
951.1 |
260.7 |
16.1 |
4.7 |
269.5 |
85.8 |
312.4 |
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| Divestments |
(0.6) |
- |
(0.2) |
- |
- |
- |
(0.6) |
- |
(0.6) |
| Production |
(8.5) |
- |
(76.8) |
- |
(1.6) |
- |
(22.9) |
- |
(22.9) |
Drilling, Development,
Revisions |
11.7 |
(9.7) |
48.5 |
(2.6) |
0.4 |
(0.5) |
20.2 |
(10.6) |
14.9 |
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Reserves at
December 31, 2002 |
105.2 |
33.4 |
1,001.9 |
277.6 |
16.0 |
4.6 |
288.2 |
84.3 |
330.4 |
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The present value of the reserves at December 31, 2002 increased over 24% from the prior period using a 12%
discount rate. Net asset value per trust unit increased by 11% on a year-over-year basis. This is significant
considering the increase of 19% in the number of outstanding trust units at December 31, 2002, versus
December 31, 2001. The increased value was primarily driven by an increase in commodity pricing and reserves.
The natural gas and oil price forecasts used by Sproule Associates Limited ("Sproule") were significantly higher
as compared to the prior year. Positive established reserve revisions and additions resulting from our successful
development programs also helped increase net asset value per trust unit.
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| Total established reserves at December 31, 2001 |
$ |
1,785.4 |
$ |
1,610.3 |
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| Proven, producing |
|
1,805.7 |
|
1,665.5 |
| Proven, non-producing |
|
225.0 |
|
194.0 |
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| Total proven |
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2,030.7 |
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1,859.5 |
| Probable @ 50% |
|
163.3 |
|
137.8 |
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| Total established reserves at December 31, 2002 |
$ |
2,194.0 |
$ |
1,997.3 |
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| Net asset value per Trust Unit as at December 31, 2001(¹) |
$ |
20.46 |
$ |
17.94 |
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| Present value of established reserves at December 31, 2002 |
$ |
2,194.0 |
$ |
1,997.3 |
| Undeveloped acreage and seismic (acreage valued at $50/acre) |
|
23.2 |
|
23.2 |
| Bank debt |
|
(361.7) |
|
(361.7) |
| Working capital excluding distributions to Unitholders |
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(2.5) |
|
(2.5) |
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| Net asset value |
$ |
1,853.0 |
$ |
1,656.3 |
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| Net asset value per Trust Unit as at December 31, 2002 ² |
$ |
22.35 |
$ |
19.98 |
Enerplus' net asset value is measured with reference to the present value of future net cash flows from our reserves
as estimated by independent reserve engineers, Sproule Associates Limited, plus land values, adjusted for working
capital and long-term debt at year-end. This calculation can vary significantly depending on the oil and natural
gas price assumptions used by Sproule. In addition, this calculation ignores "going concern" value and assumes
only the reserves identified in the Sproule report with no further acquisitions, despite our 17-year history of
replacing production through acquisition and development.
Reserve Determination Methodologies
Sproule has evaluated 84% of the total value (discounted at 12%) of the Fund's year-end reserves. All evaluations
of future net production revenues set forth in the tables are stated without provision for income taxes, general
and administrative costs and management fees, which may apply. Probable reserves and values, as reflected under
Established Reserves, have been reduced by a factor of 50% to adjust for risk.
Enerplus follows the Canadian practice of reporting gross production and reserve volumes, which are prior to the
deduction of royalties and similar payments. In the U.S., production and reserve volumes are reported after
deducting these amounts. The Canadian practice of using escalating prices and costs when estimating the
quantities of reserves is also followed by Enerplus. In the U.S., reserve estimates are calculated using prices and
costs held constant at amounts in effect at the date of the reserve report. Enerplus also follows the Canadian
practice of using "Established Reserves", which include proven reserves and the probable reserves portion that has
been reduced by a risk factor of 50%. As a consequence, our production volumes and reserve estimates may not
be comparable to those made by U.S. companies.
The present value of future cash flow at December 31, 2002 was based upon crude oil and natural gas pricing
assumptions prepared by Sproule. These forecasts are adjusted for reserve quality, transportation charges and the
provisions of any applicable sales contracts. The base reference prices and exchange rate used by Sproule are
as follows:
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| 2003 |
$ |
25.99 |
$ |
38.43 |
$ |
5.72 |
0.633 |
| 2004 |
|
23.60 |
|
34.82 |
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5.21 |
0.630 |
| 2005 |
|
21.63 |
|
32.22 |
|
4.60 |
0.620 |
| 2006 |
|
21.96 |
|
32.78 |
|
4.27 |
0.620 |
| 2007 |
|
22.29 |
|
33.90 |
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4.42 |
0.610 |
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| Prices escalated at a rate of 1.5% per year thereafter, exchange rate held constant. |
MARKETING AND COMMODITY PRICING
Natural Gas
The Fund's production was 56% weighted to natural gas throughout 2002. The
price that Enerplus realizes for its natural gas production is based on the relevant
North American pricing benchmarks: western Canadian natural gas is priced with
reference to AECO Hub in Alberta, and U.S. natural gas is priced with reference
to NYMEX at Henry Hub, Louisiana.
During 2002, the AECO monthly gas price index averaged CDN$4.07/Mcf,
representing a decrease of 35% from the prior year. The NYMEX monthly gas
price index averaged US$3.25/Mcf, representing a decrease of 26% from 2001. In
both cases, there was a large price spike early in 2001 that significantly affected the
annual average for the 2001 indices. Natural gas prices in 2002 moderated from
the dramatic peak in 2001, however, they continued to trade in a volatile range
between the lows of CDN$2.00/Mcf in the summer, to highs of CDN$6.50/Mcf
at year-end. Record storage levels and weak economic demand at the start of the
year were offset as the year progressed by colder winter temperatures, declining
storage levels and support from strong crude oil prices.
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The Fund's overall natural gas netback price (before hedging) at the plantgate was
CDN$3.87/Mcf, representing a 21% decrease from the previous year. Enerplus'
netback price did not decrease by the same magnitude as the AECO and NYMEX
indices because the Fund has a balanced portfolio of spot sales, physical fixed price
contracts, and term downstream delivery contracts that all respond differently to
the market than the referenced indices. Nevertheless, at least 46% of the Fund's
natural gas production is being directly marketed in western Canada in the spot
market against the AECO index price. The 14% of production that is transported
to and marketed directly in the Chicago / Midwest export market is priced against
the NYMEX index price. Just over one third of the Enerplus gas production is
dedicated to aggregator netback marketing pools managed by PanAlberta Gas,
Progas Limited, and the Mirant Netback Pool (formerly managed by TransCanada
Pipelines Limited). These netback pools also include portfolios of contracts
comprised of fixed price, downstream U.S. based pricing mechanisms that served
to dampen the effect of the overall decrease in the two key indices.
With the experience of colder winter temperatures and reduced inventory in
storage, the natural gas market is expected to remain strong in 2003. The lack of
exploration success, lagging drilling activity and natural reservoir declines keep
tension on North American supplies. Demand for natural gas is dependent on the
weather and the timing and strength of a North American economic recovery and
are also linked indirectly to crude oil prices as an alternative energy source.
Consequently, the fate of crude oil prices and the political tensions in the Middle
East are expected to influence the natural gas market.
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Crude Oil
The price that Enerplus receives for its crude oil is dependant upon a number of
factors including the standard North American pricing benchmark, known as West
Texas Intermediate ("WTI"), the Canadian/U.S. dollar exchange rate, hedging
activity and the specific gravity of the crude oil. Crude oil with a light specific
gravity trades at a premium to medium and heavier blends of crude oil that require
more refining effort. As shown in the pie chart, 85% of Enerplus' crude oil and
NGL stream is classified as either light or medium gravity.
The 2002 average price for the benchmark WTI crude oil was US$26.08/bbl, an
increase of only one percent when compared to the 2001 price. It is interesting to
note that where 2001 oil prices started the year at high levels (US$30.00/bbl) and
ended the year much lower (US$18.00/bbl), in an almost mirror image, 2002 saw
the lowest prices in January, with prices climbing steadily to a peak exceeding
US$32.00/bbl by year-end. The early perceptions of weak economic demand and
surplus crude oil inventories gave way later in the year to the political uncertainties
surrounding Iraq and the Middle East, and strike-induced supply disruptions in
Venezuela. Crude oil prices may continue to be volatile as the political tensions in
the Middle East remain unresolved.
The Fund's average netback price for its crude oil production (before hedging) was
CDN$34.37/bbl which reflects a 13% increase over that of 2001. Enerplus sells all
of its crude oil at the lease site to marketers and refiners on contracts that fluctuate
with monthly spot prices. The Fund realized a greater year-over-year increase than
the WTI benchmark for two reasons. The refining differential applied to heavier
grade crude decreased substantially from US$10.65/bbl in 2001 to US$6.45/bbl
in 2002. The weaker Canadian dollar allowed Enerplus to realize higher
prices as Enerplus' crude oil is priced with reference to the U.S. dollar
denominated benchmarks.
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